Petroleum deposits of crude oil demonstrate significant variations across in-situ reservoir and fluid properties. Deposits of high viscosity or low API gravity oils (higher density oils) can grade from increasingly difficult to economically produce to being uneconomic to produce under initial reservoir conditions. The limiting physical properties of heavier oils controlling economic flow rates to producing wells, such as the oil viscosity, can be strongly improved by heating. At a higher initial in-situ temperature, a range of recovery techniques that would otherwise not be economically feasible can become effective.
Oil sand deposits are found predominantly in the Middle East, Venezuela, and Western Canada. The Canadian bitumen deposits, being the largest in the world, are estimated to contain between 1.6 and 2.5 trillion barrels of oil, so the potential economic benefit of this invention carries significance within this resource class. The term “oil sands” refers to large subterranean land forms composed of reservoir rock, water and bitumen. They comprise layers of bitumen-rich deposits, which may be internally continuous permitting vertical fluid flow, or otherwise segregated with flow barriers into discrete, adjacent layers. Bitumen is a heavy, black oil which, due to its high viscosity, cannot readily be pumped from the ground like other crude oils. Therefore, alternate processing techniques must be used to extract the bitumen deposits from the oil sands, which remain a subject of active development in the field of practice. The basic principle of known extraction processes is to lower the viscosity of the bitumen by applying heat, injecting chemical solvents, or a combination thereof, to a deposit layer, thereby promoting flow of the material throughout the treated reservoir area, in order to allow for recovery of bitumen from that layer.
FIG. 1 illustrates the relationship between bitumen viscosity and temperature, for a range of oils identified according to API gravity, or oil density. Referring to the curve for an 8 API oil, commonly within the range of Canadian Athabasca bitumen, it can be seen that at in-situ conditions of approximately 10° C., the bitumen viscosity is in the range of 6-7 million centipoise. However, for even a modest temperature increase of 40° C., the bitumen viscosity at 50° C. decreases dramatically to 20,000 cp, while in extending the formation temperature to 100° C., the viscosity would fall to less than 1,000 cp. At these reduced viscosity values, the crude's ability to flow to a producing wellbore is markedly increased. More significantly, however, the effectiveness of alternate recovery techniques applied to such a preconditioned reservoir oil becomes greatly enhanced. The application of recovery strategies to an externally, or passively, pre-heated reservoir volume forms the basis of the present invention.
A variety of known extraction processes are commercially used to recover bitumen from oil deposits. For example, Steam-Assisted Gravity Drainage, commonly referred to as SAGD, involves the injection of steam into a bitumen-containing deposit in order to directly transfer heat to the oil. Steam is a preferred fluid as the latent heat of steam, defined as the heat released when a molecule condenses from vapour to liquid phase, is one of the highest per molecule among all known fluids. This allows the maximum heat transfer per volume of cycle fluid externally introduced into the reservoir. The heat from the injected steam reduces the viscosity of the bitumen and results in mobilization of same. As known in the art, a SAGD process results in condensation of the steam into liquid water, which is in effect introduced into the reservoir as a collateral contaminant to the heat transfer process through the physical phase change of the water. The mobilized bitumen must therefore flow with the introduced water, where the relative permeability of the water/oil mixture is reduced, leading to potentially poorer oil productivity and overall recovery. In addition, the mixture can form emulsions within the deposit, which block, or retard, bitumen flow. The water is also recovered with the bitumen, necessitating additional costs for pumping, separation and treating at surface, while also acting to remove heat within the produced fluid volumes. Consequently, while water is a pragmatic heat transfer medium, it also introduces a range of undesirable consequences for bitumen recovery.
Furthermore, the SAGD process is only an economically feasible option for larger deposits as measured by metrics of minimum formation thickness or bitumen volume. For example, it is common in the art to use SAGD processes only on deposits having a threshold thickness, commonly greater than 15-20 m, dependent on specific considerations such as ore grade or economic limitations subject to the evolving fiscal regime. The economics of a SAGD process are directly influenced by the costs of handling the water circulation through the reservoir. Consequently, an alternate technique to remove the need for water handling in heating a formation would be of strong economic benefit. Such a process can be achieved by heating an oil deposit externally, where the complications developed in the art introducing heat into a reservoir directly, or from within a producing zone, are eliminated.
Dilution is another technique with potential application in the extraction of bitumen from oil sand or heavy oil deposits. A dilution process involves the injection of a physical solvent, such as light alkanes or other relatively light hydrocarbons, into a deposit, similar to the procedure used in steam injection, to dissolve heavy oil or bitumen in the solvent. This technique also reduces the viscosity of the bitumen, thereby allowing the recovery of the bitumen-solvent mixture that is mobilized throughout the reservoir. Condensing hydrocarbon solvents have also been proposed in the literature, where a reduced level of heat is introduced in the reservoir from the vapour to liquid phase change, in addition to the subsequent solvent dilution effect. See for example: Nenniger, J. E. and Dunn, S. G., “How Fast is Solvent Based Gravity Drainage?”, CIPC 59th Annual Technical Meeting, Calgary, Jun. 17-19, 2008, paper 2008-139). However, the condensing hydrocarbon strategy is a further example where heat is introduced directly to the produced zone by means of the working fluid.
Solvents that can be used in effective dilution strategies include lower molecular weight alkanes (ethane through to dodecane), common transportation diluent mixtures, kerosene, naphta, flue gas and carbon dioxide. Carbon dioxide may be of particular interest as large quantities may otherwise be available from such processes as steam generation. Immiscible carbon dioxide injection is demonstrated to have a strong effect on bitumen viscosity reduction and can be re-circulated in a recovery process to permit a level of ultimate underground storage, or sequestration.
It is increasingly common to apply a combination of heat and dilution processes in order to recover an economically significant amount of bitumen from solvent-assisted steaming processes. Solvent aided or solvent assisted processes, SAP techniques, involve the addition of a hydrocarbon solvent to steam. Some modest success has been reported with SAP techniques, which are currently under active development. However an inherent difficulty with SAP techniques remains the introduction of liquid water into the reservoir. Water acts as an effective barrier to solvent, limiting the full efficiency of solvent in a SAP process. Thus, known SAP processes remain disadvantageous by introducing water into the reservoir.
Consequent to the net removal of bitumen and related fluids from a reservoir, pressure depletion would develop within the deposit. This could deter from bitumen production by impeding the reservoir energy for artificial lift of fluids to surface, or create a pressure sink for fluid migration, such as in bounding water zones, to enter the treated zone. The above mentioned recovery processes use the injection of fluids, such as steam or solvents, to replace the volume occupied by the extracted bitumen within the deposit, thus preventing the development of reservoir pressure depletion. The injection of a solvent, such as for example CO2, to replace reservoir voidage within a preheated working chamber can be used to advantage as both providing pressure maintenance and as a dilution agent as outlined in this invention.
Thermal processes for bitumen recovery within a deposit inherently involve heat losses to surrounding rock strata. Due to the physical nature of a petroleum deposit, heat introduced into a bitumen reservoir is dissipated throughout the target area and is conducted to surrounding structures including adjacent hydraulically isolated bitumen deposits. This results in higher process cost, as a portion of the energy supplied to heat the target bitumen area is transferred to other regions within the deposit, resulting in a loss of thermal efficiency.
The prior art methods of bitumen recovery have focused primarily on transferring heat directly to or generating heat directly within the targeted reservoir and extracting production directly from the same single hydraulically continuous stratum within an oil sand or heavy oil reservoir. This strategy is logically inherent to a steaming process, as the highest temperature with more favoured changes or improved bitumen characteristics (lowest viscosity) is achieved at the entry point of steam injection within a reservoir. Prior to further heat losses, heavy oil or bitumen removed at this point has the best physical flow properties for optimal productivity and/or recovery. Heated bitumen, initial formation waters, water condensed from injected steam and non-condensable gases are extracted from the formation to which heat was initially supplied. Heat losses to the bounding formation is accepted as a necessary physical consequence of the thermal process in a SAGD operation. Consequently, SAGD suffers from both thermal inefficiencies of heat losses outside of the producing formation and further heat losses from produced fluids within the formation.
Such prior art techniques have attempted to overcome some issues of heat loss due to lateral heat conduction to horizontally adjacent areas by incorporating a plurality of heaters, isolating the treatment area by frozen barriers, and by electrically heating an internal non-bitumen rock layer, such as an internal sequence of shale stringers, to allow heat to transfer internally directly to the desired bitumen-rich layer.
For example, U.S. Pat. Nos. 6,991,032 and 7,225,866 disclose a modified thermal process for bitumen extraction using an arrangement of several heating wells and several production wells dispersed throughout a single deposit layer. U.S. Pat. No. 7,073,578 describes a thermal process for heating two sections of a single deposit using two sets of heating sources, one for each section, and leaving a third, unheated section between them.
There are several patents describing recovery techniques for extracting kerogen from solid oil shale layers within an oil sand deposit. For example, U.S. Pat. Nos. 4,886,118; 6,722,431; and 7,040,400 refer specifically to the recovery of kerogen from an oil shale layer within a single deposit. They relate to a deposit having layers of varying permeability that are conductively heated from either a heat source applied to another portion of the deposit, or applied directly to the oil shale layer.
Other examples of known bitumen recovery processes are provided in the following: U.S. Pat. Nos. 7,077,198; 4,926,941; 5,042,579; 5,060,726; and WO/2008/048454
In general, the prior art methods have primarily focused on producing bitumen from within a single reservoir or stratum. However, in some cases, bitumen deposits are located in vertically adjacent reservoirs or stratum separated by a natural barrier. Such barriers hydraulically restrict the movement of fluids between layers, but do not restrict heat transfer between layers as the reservoir rock in such barriers does not provide an insulating capacity limiting heat conduction. Such barriers may be a geological formation, such as rock, shale, or mudstone. In such cases, it is common for a separate heating and production process to be carried out for both strata, where specific economic criteria permit (such as adequate pay thickness, hydrocarbon saturation and reservoir permeability). If the economic criteria for individual layer exploitation are not met, then either all or a subset of the layers may not be exploitable by SAGD. Further, in the case of SAGD, the injection of steam in both regions extends the problems associated with the mixing of water and bitumen and related thermal inefficiencies. Therefore, there exists a need for an improved bitumen recovery process.
Consequently, the essence of the invention is to provide a means to precondition a reservoir oil volume by indirect, or passive heat conduction from heat-generating operations in an adjacent, hydraulically isolated layer. Once heated, a range of techniques for production operations in the adjacent layer can then be optimally designed and applied.